Eog Resources Misses

Eog Resources (EOG) reported a 3rd Quarter September 2016 loss of $0.40 per share on revenue of $2.1 billion. The consensus estimate was a loss of $0.31 per share on revenue of $1.9 billion. The Earnings Whisper number was for a loss of $0.25 per share. Revenue fell 2.5% compared to the same quarter a year ago.

EOG Resources Inc explores for, develops, produces and markets crude oil and natural gas in the USA, Trinidad, United Kingdom, China, Argentina and, from time to time, select other international areas.

EOG Resources, Inc. (EOG) today reported a third quarter 2016 net loss of $190.0 million, or $0.35 per share. This compares to a third quarter 2015 net loss of $4.1 billion, or $7.47 per share.

Adjusted non-GAAP net loss for the third quarter 2016 was $220.8 million, or $0.40 per share, compared to adjusted non-GAAP net income of $13.5 million, or $0.02 per share, for the same prior year period. Adjusted non-GAAP net income (loss) is calculated by matching hedge realizations to settlement months and making certain other adjustments in order to exclude non-recurring and certain other items. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Lower crude oil and natural gas prices more than offset significant well productivity improvements and lease and well cost reductions, resulting in decreases in adjusted non-GAAP net income, discretionary cash flow and EBITDAX during the third quarter 2016 compared to the third quarter 2015. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Operational Highlights U.S. crude oil volumes of 275,700 barrels of oil per day (Bopd) in the third quarter 2016 exceeded the midpoint of the companys guidance by 3 percent. Compared to the same prior year period, lease and well expenses decreased 18 percent on a per-unit basis.

In the third quarter 2016, total crude oil production increased 1 percent while exploration and development expenditures (excluding property acquisitions) decreased 32 percent, compared to the same period last year. Natural gas liquids production increased 5 percent, while total natural gas production for the third quarter 2016 decreased 10 percent versus the same prior year period.

"Even in a low commodity price environment, 2016 is proving to be a breakout year for EOG with record well productivity, sustainable cost reductions and organic growth in all our core plays, coupled with a historic transaction that adds substantial high-return growth potential," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "EOGs third quarter accomplishments reflect the hard work and ingenuity of our great employees and our unique culture."

2020 Crude Oil Production Outlook and 2016 Capital Plan Update As a result of continued improvements in capital efficiency which have been augmented by the Yates transaction, EOG is increasing its crude oil organic production growth outlook through 2020. The long term outlook includes growth from key areas such as the Eagle Ford, Delaware Basin, Rockies and the Bakken. In addition to the growth illustrated in the outlook, the company continues to evaluate high-quality emerging plays through its ongoing exploration efforts.

Assuming balanced spending including dividend payments and a flat $50 West Texas Intermediate crude oil (WTI) price, EOG now expects 15 percent compound annual crude oil production growth through 2020. If the assumed WTI price is increased to $60, EOG would expect 25 percent compound annual crude oil production growth through 2020. This reflects an increase from the companys prior outlook of 10 to 20 percent growth at $50 to $60 WTI.

"EOGs future has never been brighter, and we are already in a position to make a material improvement to the long-term outlook we provided last quarter," Thomas said. "The company-wide premium drilling strategy and the recently closed Yates transaction are significantly boosting capital efficiency and enabling us to extend our lead in unconventional resource productivity."

For 2016, EOG is increasing its capital spending guidance range by $200 million to $2.6 to $2.8 billion, excluding acquisitions. The spending increase will be directed toward well completions, which are now targeted to increase from the initial plan of 270 and the prior revised forecast of 350 to 450 net wells in 2016. Drilling productivity continues to improve, and the company now expects to drill 290 net wells, 40 more than its prior forecast and 90 more than its original 2016 plans.

Delaware Basin EOG increased its Delaware Basin net resource potential by 155 percent to 6.0 billion barrels of oil equivalent (BnBoe) in the third quarter 2016 (inclusive of the recent Yates transaction). Delaware Basin net well locations increased by 27 percent to 6,330. The average planned lateral length for these locations increased from 4,500 feet to over 7,000 feet.

"With the Yates transaction, EOGs Delaware Basin position now exceeds 400,000 net acres in the core window of this world-class play," Thomas said. "Our technical and operational advances applied to the combined assets have produced a major increase in EOGs Delaware Basin potential. As we continue to make advances in cost management and technology, we believe our resource potential over time will continue to increase in both size and quality."

In the Delaware Basin Wolfcamp, EOG increased its net resource potential from 1.3 BnBoe to 2.9 BnBoe and net well locations from 2,130 to 2,660. For the Delaware Basin Wolfcamp oil play, EOGs average gross reserves per well increased to 1,330 thousand barrels of crude oil equivalent (MBoe) from 750 MBoe, while average gross reserves per well increased to 1,550 MBoe from 900 MBoe in the combo portion of the play.

For the Delaware Basin Second Bone Spring, EOG increased its net resource potential from 0.5 BnBoe to 1.4 BnBoe and net well locations from 1,250 to 1,870. Average gross reserves per well increased to 950 MBoe from 500 MBoe.

EOG also increased its Delaware Basin Leonard net resource potential from 0.6 BnBoe to 1.7 BnBoe and net well locations from 1,600 to 1,800. Average gross reserves per well increased to 1,175 MBoe from 500 MBoe.

In the third quarter 2016, EOG completed 22 wells in the Delaware Basin Wolfcamp with an average treated lateral length of 4,800 feet per well and an average 30-day initial production rate per well of 2,350 barrels of oil equivalent per day (Boed), or 1,675 Bopd, 275 barrels per day (Bpd) of natural gas liquids (NGLs) and 2.4 million cubic feet per day (MMcfd) of natural gas. In the Delaware Basin Second Bone Spring, EOG completed four wells in the third quarter with an average treated lateral length of 4,600 feet per well and an average 30-day initial production rate per well of 1,240 Boed, or 940 Bopd, 120 Bpd of NGLs and 1.1 MMcfd of natural gas.

South Texas Eagle Ford EOGs oil-rich South Texas Eagle Ford acreage continued to deliver exceptional results in the third quarter 2016 and was once again the largest contributor to EOGs U.S. crude oil production.

In the third quarter, EOG completed 47 wells in the Eagle Ford with an average treated lateral length of 5,700 feet per well and an average 30-day initial production rate per well of 1,825 Boed, or 1,425 Bopd, 190 Bpd of NGLs and 1.3 MMcfd of natural gas.

Rockies and the Bakken In the third quarter, EOG completed nine wells in the Powder River Basin with an average 30-day initial production rate per well of 1,560 Boed, or 840 Bopd, 245 Bpd of NGLs and 2.8 MMcfd of natural gas.

In the DJ Basin Codell in Wyoming, EOG completed five wells in the third quarter with an average 30-day initial production rate per well of 720 Boed, or 610 Bopd, 70 Bpd of NGLs and 0.3 MMcfd of natural gas.

In the North Dakota Bakken, EOG completed 13 wells in the third quarter with an average 30-day initial production rate per well of 850 Boed, or 763 Bopd, 45 Bpd of NGLs and 0.3 MMcfd of natural gas.

Hedging Activity For the period November 1 through December 31, 2016, EOG has crude oil financial price collar contracts in place for 70,000 Bopd at an average ceiling price of $54.25 per barrel and an average floor price of $45.00 per barrel.

For the period March 1 through November 30, 2017, EOG has natural gas financial price swap contracts in place for 30,000 million British thermal units (MMBtu) per day at a weighted average price of $3.10 per MMBtu.

For the period March 1 through November 30, 2017, EOG sold natural gas call option contracts for 213,750 MMBtu per day at an average strike price of $3.44 per MMBtu. For the period March 1 through November 30, 2018, EOG sold natural gas call option contracts for 120,000 MMBtu per day at an average strike price of $3.38 per MMBtu.

For the period March 1 through November 30, 2017, EOG purchased natural gas put option contracts for 171,000 MMBtu per day at an average strike price of $2.92 per MMBtu. For the period March 1 through November 30, 2018, EOG purchased natural gas put option contracts for 96,000 MMBtu per day at an average strike price of $2.94 per MMBtu.

A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables.

Capital Structure and Asset Sales At September 30, 2016, EOGs total debt outstanding was $7.0 billion with a debt-to-total capitalization ratio of 37 percent. Taking into account cash on the balance sheet of $1.1 billion at the end of the third quarter, EOGs net debt was $5.9 billion with a net debt-to-total capitalization ratio of 33 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.

Proceeds from asset sales this year to date total $625 million. This includes proceeds from a transaction that has already closed in the fourth quarter 2016. Associated production of the divested assets was 80 MMcfd of natural gas, 3,400 Bopd and 4,290 Bpd of NGLs.

Conference Call November 4, 2016 EOGs third quarter 2016 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Friday, November 4, 2016. To listen, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview.

EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.

This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOGs future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOGs management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOGs future operating results and returns or EOGs ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOGs forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOGs control. Important factors that could cause EOGs actual results to differ materially from the expectations reflected in EOGs forward-looking statements include, among others:

• the extent to which EOG is successful in its efforts to acquire or discover additional reserves;

• the extent to which EOG is successful in its efforts to economically develop its acreage in, produce reserves and achieve anticipated production levels from, and maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects;

• the extent to which EOG is successful in its efforts to market its crude oil and condensate, natural gas liquids, natural gas and related commodity production;

• the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOGs ability to retain mineral licenses and leases;

• the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations; environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;

• EOGs ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;

• the extent to which EOGs third-party-operated crude oil and natural gas properties are operated successfully and economically;

• competition in the oil and gas exploration and production industry for the acquisition of licenses, leases and properties, employees and other personnel, facilities, equipment, materials and services;

• the availability and cost of employees and other personnel, facilities, equipment, materials (such as water) and services;

• the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;

• weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression and transportation facilities;

• the ability of EOGs customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;

• EOGs ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;

• political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates;

-- the use of competing energy sources and the development of alternative energy sources;

• the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;

-- acts of war and terrorism and responses to these acts;

-- physical, electronic and cyber security breaches; and

• the other factors described under ITEM 1A, Risk Factors, on pages 13 through 21 of EOGs Annual Report on Form 10-K for the fiscal year ended December 31, 2015, and any updates to those factors set forth in EOGs subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by EOGs forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOGs forward-looking statements. EOGs forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SECs latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOGs Annual Report on Form 10-K for the fiscal year ended December 31, 2015, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SECs website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.

(A) Thousand barrels per day or million cubic feet per day, as applicable.

(B) Other International includes EOGs United Kingdom, China and Canada operations.

(C) Dollars per barrel or per thousand cubic feet, as applicable.

Excludes the impact of financial commodity derivative instruments.

(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas.

Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas.

MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

(E) Includes revenue adjustment of $3.62 per Mcf and $1.19 per Mcf for the quarter and year-to-date, respectively, related to a price adjustment for natural gas sales made in China from June 2012 to March 2015.

The following chart adjusts the three-month and nine-month periods ended September 30, 2016 and 2015 reported Net Loss (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2016 and 2015, to eliminate the impact of the Texas margin tax rate reduction in 2015, to add back severance costs associated with EOGs North American operations in 2015, to eliminate the impact of the Trinidad tax settlement in 2016, to add back certain voluntary retirement expense in 2016, to add back impairment charges related to certain of EOGs assets in 2016 and 2015, and to add back acquisition costs related to the Yates transaction in 2016.

EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items.

EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities.

EOG management uses this information for comparative purposes within the industry.

The following chart adjusts the three-month and nine-month periods ended September 30, 2016 and 2015 reported Net Loss (GAAP) to Earnings Before Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net (gains) losses on asset dispositions.

EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (Loss) (GAAP) to add back Interest Expense, Income Taxes (Income Tax Benefit), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items.

EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

Three Months Ended

Nine Months Ended

September 30,

September 30,

2016

2015

2016

2015

Net Loss (GAAP)

$

(190,000)

$

(4,075,739)

$

(954,334)

$

(4,240,219)

Adjustments:

Interest Expense, Net

70,858

60,571

210,356

174,400

Income Tax Benefit

(82,250)

(2,199,182)

(409,161)

(2,282,511)

Depreciation, Depletion and Amortization

899,511

722,172

2,690,893

2,544,187

Exploration Costs

25,455

31,344

85,843

114,548

Dry Hole Costs

10,390

198

10,464

14,317

Impairments

177,990

6,307,420

322,321

6,445,375

EBITDAX (Non-GAAP)

911,954

846,784

1,956,382

2,770,097

Total (Gains) Losses on MTM Commodity Derivative Contracts

(5,117)

(29,239)

33,821

(56,954)

Net Cash Received from (Payments for) Settlements of Commodity

Derivative Contracts

(25,071)

99,879

(22,219)

661,021

(Gains) Losses on Asset Dispositions, Net

(108,204)

1,185

(101,801)

5,142

Adjusted EBITDAX (Non-GAAP)

$

773,562

$

918,609

$

1,866,183

$

3,379,306

Adjusted EBITDAX (Non-GAAP) - Percentage Decrease

-16%

-45%

EOG RESOURCES, INC.

Quantitative Reconciliation of Net Debt (Non-GAAP) and Total

Capitalization (Non-GAAP) as Used in the Calculation of

the Net Debt-to-Total Capitalization Ratio (Non-GAAP) to

Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP)

(Unaudited; in millions, except ratio data)

The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation.

A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown.

EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation.

EOG management uses this information for comparative purposes within the industry.

Presented below is a comprehensive summary of EOGs crude oil price swap contracts through November 3, 2016, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil Price Swap Contracts

Weighted

Volume

Average Price

(Bbld)

($/Bbl)

2016

April 12, 2016 through April 30, 2016 (closed)

90,000

$

42.30

May 1, 2016 through June 30, 2016 (closed)

128,000

42.56

EOG has entered into crude oil collar contracts, which establish ceiling and floor prices for the sale of notional volumes of crude oil as specified in the collar contracts.

The collars require that EOG pay the difference between the ceiling price and the average NYMEX West Texas Intermediate crude oil price for the contract month (Index Price) in the event the Index Price is above the ceiling price.

The collars grant EOG the right to receive the difference between the floor price and the Index Price in the event the Index Price is below the floor price.

Presented below is a comprehensive summary of EOGs crude oil collar contracts through November 3, 2016, with notional volumes expressed in Bbld and prices expressed in $/Bbl.

Crude Oil Collar Contracts

Weighted Average Price ($/Bbl)

Volume (Bbld)

Ceiling Price

Floor Price

2016

September 1, 2016 through October 31, 2016 (closed)

70,000

$

54.25

$

45.00

November 1, 2016 through December 31, 2016

70,000

54.25

45.00

Presented below is a comprehensive summary of EOGs natural gas price swap contracts through November 3, 2016, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.

Natural Gas Price Swap Contracts

Weighted

Volume

Average Price

(MMBtud)

($/MMBtu)

2016

March 1, 2016 through August 31, 2016 (closed)

60,000

$

2.49

2017

March 1, 2017 through November 30, 2017

30,000

$

3.10

EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts.

The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price.

In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts.

The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price.

Presented below is a comprehensive summary of EOGs natural gas call and put option contracts through November 3, 2016, with notional volumes expressed in MMBtud and prices expressed in $/MMbtu.

Natural Gas Option Contracts

Call Options Sold

Put Options Purchased

Weighted

Weighted

Volume

Average Price

Volume

Average Price

(MMBtud)

($/MMBtu)

(MMBtud)

($/MMBtu)

2016

September 2016 (closed)

56,250

$

3.46

-

$

-

October 1, 2016 through November 30, 2016 (closed)

106,250

3.48

-

-

2017

March 1, 2017 through November 30, 2017

213,750

$

3.44

171,000

$

2.92

2018

March 1, 2018 through November 30, 2018

120,000

$

3.38

96,000

$

2.94

Definitions

Bbld

Barrels per day

$/Bbl

Dollars per barrel

MMBtud

Million British thermal units per day

$/MMBtu

Dollars per million British thermal units

NYMEX

New York Mercantile Exchange

EOG RESOURCES, INC.

Direct After-Tax Rate of Return (ATROR)

The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated proved reserves ("net" to EOGs interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be).

As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements.

Direct ATROR

Based on Cash Flow and Time Value of Money

- Estimated future commodity prices and operating costs

- Costs incurred to drill, complete and equip a well, including facilities

Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively

(Unaudited; in millions, except ratio data)

The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations.

EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations.

EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry.

(a) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2015:

Year Ended December 31, 2015

Before

Income Tax

After

Tax

Impact

Tax

Adjustments:

Add:

Mark-to-Market Commodity Derivative Contracts Impact

$

668

$ (238)

$ 430

Add:

Impairments of Certain Assets

6,308

(2,183)

4,125

Less:

Texas Margin Tax Rate Reduction

-

(20)

(20)

Add:

Legal Settlement - Early Leasehold Termination

19

(6)

13

Add:

Severance Costs

9

(3)

6

Add:

Net Losses on Asset Dispositions

9

(4)

5

Total

$

7,013

$ (2,454)

$ 4,559

(b) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2014:

Year Ended December 31, 2014

Before

Income Tax

After

Tax

Impact

Tax

Adjustments:

Less:

Mark-to-Market Commodity Derivative Contracts Impact

$

(800)

$ 285

$ (515)

Add:

Impairments of Certain Assets

824

(271)

553

Less:

Net Gains on Asset Dispositions

(508)

21

(487)

Add:

Tax Expense Related to the Repatriation of Accumulated

Foreign Earnings in Future Years

-

250

250

Total

$

(484)

$ 285

$ (199)

(c) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2013:

Year Ended December 31, 2013

Before

Income Tax

After

Tax

Impact

Tax

Adjustments:

Add:

Mark-to-Market Commodity Derivative Contracts Impact

$

283

$ (101)

$ 182

Add:

Impairments of Certain Assets

7

(3)

4

Less:

Net Gains on Asset Dispositions

(198)

61

(137)

Total

$

92

$ (43)

$ 49

EOG RESOURCES, INC.

Fourth Quarter and Full Year 2016 Forecast and Benchmark Commodity Pricing

(a)

Fourth Quarter and Full Year 2016 Forecast

The forecast items for the fourth quarter and full year 2016 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release.

EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

This forecast, which should be read in conjunction with the accompanying press release and EOGs related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast.

(b)

Benchmark Commodity Pricing

EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month.

EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month.